In order to analyze the amount of oil contained in a particular soil at a particular depth in a subterranean well, a core or core sample of the well formation typically is extracted and brought to the surface for analysis. If the core sample has retained its mechanical and chemical integrity during the trip from downhole to the surface, then an analysis of the core sample will yield accurate data about the percent of fluid and/or gas contained in the formation. The resulting data then may be used to determine what type(s) of fluid--especially oil--are contained in the formation.
Unfortunately, it is difficult to maintain the mechanical and/or chemical integrity of the core sample during its journey from downhole to the surface. Downhole, the oil and/or water in the formation may contain dissolved gas which is maintained in solution by the extreme pressure exerted on the fluids when they are in the formation. Unless a pressure core barrel is used, the pressure on the core when the core is downhole will differ dramatically from the pressure on the core sample as the core sample is brought to the surface.
As the pressure on the core sample decreases during the trip to the surface, the fluids in the core tend to expand, and any gas that is dissolved in the sample fluids will tend to come out of solution. In addition, any "mobile oil," or oil that passes through the core in a manner dependent on the permeability, porosity, and/or volume of fluid contained therein, may drain or bleed out of the core and be lost. If protective measures are not taken, then this sellable gas, mobile oil, and/or some water may be lost during transport of the core to the surface. As a result, the core sample will not accurately represent the composition of the downhole formation.
One means for dealing with the foregoing problem is pressure coring, or transporting the core to the surface while maintaining the downhole pressure on the core. Pressure coring helps to maintain both the mechanical and the chemical integrity of the core. However, pressure coring is expensive for a number of reasons, including: the manpower required; the many difficulties that must be overcome to effectively handle the pressurized core; and, the expensive procedures required to analyze the pressurized core once it reaches the surface.
Another technique that has been used in an attempt to maintain core integrity is "sponge coring." In sponge coring, an absorbent sponge or foam material is disposed about the core so that fluids forced out of the core during depressurization are absorbed by the adjacent sponge layer. Sponge coring has a number of disadvantages.
Sponge coring typically does not provide accurate data regarding the structure of the formation due to inadequate saturation, and because the wettability of the sponge varies with variations in temperature and pressure. Also, the sponge does not protect the core from the drastic changes in pressure experienced during transport of the core to the surface. Thus, the core geometry or mechanical integrity of the core sample may not be preserved during sponge coring. Also, even though the sponge may absorb some of the gas and/or oil that escapes from the core sample, some of that gas and/or oil also may be lost during transport. Finally, in order for the sponge sleeve to protect the core, the sponge sleeve must be in close contact with the core. Close contact is difficult to achieve in broken or unconsolidated cores. And, because of the high friction coefficient of the sponge, close contact between the sponge and the core can result in jamming within the coring tool even where the core is hard and consolidated.
Some improvement in sponge coring has been achieved by at least partially saturating the sponge with a pressurized fluid that (1) prevents drilling mud from caking on the sides of the core, and (2) prevents fluid loss from the core. The pressurized fluid is displaced from the sponge as the core enters the core barrel and compresses the sponge lining. Unfortunately, as a practical matter, "perfect saturation" of the sponge is impossible. Air tends to remain trapped in the sponge and skew the final analysis of the formation. Even if the sponge is presaturated, gas and solution gas expelled from the core sample tends to be lost. As a result, the sponge does not accurately delineate the gas held in the formation. For these and other reasons, sponge coring, even with presaturation, leaves much to be desired.
Other techniques for maintaining core integrity involve changing the composition of the drilling mud so that the drilling mud does not contaminate the core. In one such technique, a polymer containing two or more recurring units of two different polymers is incorporated in the drilling fluid in order to minimize the variation in rheological properties at ambient versus high downhole temperatures. In another technique, an oil based fluid containing an organophilic clay gelation agent is mixed with the mud to regulate the thixotropic qualities of the drilling mud or packer fluid. In some of these techniques, the drilling mud actually surrounds and gels to form a capsule around the core sample.
Unfortunately, contact between a core sample and the drilling mud or coring fluid is one of the more common factors leading to contamination and unreliability of the core sample. Therefore, it is desirable to minimize contact between the drilling mud and the core sample. The potential for contamination renders it undesirable to use the drilling mud, itself, as an encapsulating agent.
Still others have used thermoplastics and thermosetting synthetics to encapsulate the core sample inside of the core barrel before transporting the sample to the surface. The disadvantage of these techniques is that thermoplastics and thermosetting synthetics require a chemical reaction to harden or viscosify.
Many factors downhole are capable of influencing or even interfering with the chemical reaction required to "harden" a thermoplastic or thermosetting resin. In fact, the chemical reaction required to harden some of these materials is, itself, exothermic. The exothermicity of the chemical reaction may affect the timing of the encapsulation and the mechanical and/or chemical integrity of the resulting core sample. Similarly, oil contained in the reservoir may contain gas which comes out of solution before the chemical reaction is complete.
The fact that an exothermic chemical reaction may occur in the encapsulating resin at the same time that gas may be liberated from the oil in the core sample also renders the sampling procedure unsafe. For example, the escaping gas may explode when exposed to the sudden increase in temperature produced by the hardening reaction.
Other techniques for maintaining core integrity involve attempts to remove contaminants from the core before the core is depressurized. One such technique is to flush the core before depressurization and to lubricate and/or wash the core as it enters the core barrel. Although such techniques may help to maintain core "integrity" after flushing, the flushing, itself, alters the original content of the core and renders the core sample inherently unreliable.
Some have attempted to develop compositions to envelope the core and prevent any change in core composition until the envelope is removed. In one such technique, an aqueous gel, such as carboxymethylhydroxyethylcellulose (CMHEC), is mixed with an aqueous brine solution and an alkaline earth metal hydroxide, such as calcium hydroxide, to form a gel which serves as a water diversion agent, a pusher fluid, a fracturing fluid, a drilling mud, or a workover or completion fluid. In another such technique, material with colligative properties, particularly a carbohydrate such as sucrose or starch, and optionally a salt, such as potassium chloride, has been added to the drilling mud to mitigate the osmotic loss of the aqueous phase of the drilling mud. Still others have tried pumping an oleophilic colloid through the drill string so that the colloid contacts and is dispersed in an oleaginous liquid forming gel which tends to plug the formation.
Unfortunately, none of these techniques has been completely successful in maintaining the mechanical and chemical integrity of a core sample during transport from downhole to the surface. Also, many of these techniques either are expensive or difficult, and may be dangerous to perform.
Core samples have been successfully protected using encapsulating materials which increase in viscosity with the natural decrease in temperature as the core sample is transported from downhole to the surface. Such encapsulating materials include polyalkylene derivatives, such as polyethylene, ethylene vinyl acetate copolymer, and polyglycols, such as polyethylene glycol or polypropylene glycol.
Polyalkylene derivatives adequately protect a core sample under most circumstances; however, there may be instances where the polyalkylene derivatives could interfere with a correct evaluation of the sample. An example is where the formation being sampled contains mainly oil and very little gas or water. Under such circumstances, it is possible that the hydrocarbons in the encapsulating material could dissolve in the crude oil in the sample and contaminate the core sample. This could interfere with a correct analysis of the degree of oil saturation of the core sample. In such circumstances, a water-soluble encapsulating material that was capable of preserving the integrity of the core sample without invading and contaminating the core sample, would be desirable.